The solar industry has undergone a tremendous evolution in the course of the last decade. Below we outline some of the more notable developments, with a focus on project financing in the U.S.

In 2007, the largest solar photovoltaic project in the world was an 11 MW project in Portugal, called Serpa, that cost EUR 58 million to build. Today, the largest solar PV project in the world is Tengger Desert Solar Park in China and is 1,500 MW, or more than 100 times the capacity of Serpa, and the cost of building a solar project is a fraction of what it was a decade ago.

In 2007, manufacturers of thin-film solar and manufacturers of crystalline silicon solar were battling to see which would be the predominant technology. Today, there are more manufacturers of crystalline modules than thin film and more projects using crystalline modules than thin film; however, First Solar appears to have found success with rigid thin-film modules.

In 2007, terms like “resi,” “C&I,” “DG” and “community solar,” which are now ubiquitous in our industry, were unknown to most energy financiers.

Furthermore, the U.S. tax equity market for solar in 2007 was nascent at best. The leading structure was the sale-leaseback. Investors were starting to experiment with early forms of a flip partnership that lagged in sophistication behind the structuring being used for wind project tax equity. If a solar company called an investment bank looking for financing, the call was directed to the venture capital desk.

Today, the partnership flip has far surpassed the sale-leaseback in use in the U.S. solar industry. In addition, there are now two distinct partnership flip structures for solar: internal rate of return-based flips that resemble those used by the wind industry and time-based flips. In addition, there are niche structures like pass-through leases and inverted leases, and in 2007, those had not yet migrated on a meaningful level to solar from the historic tax credit industry.

The investment tax credit (ITC) for which solar projects qualify has also changed in the last decade. In 2007, the ITC was still an alternative minimum tax “preference.” That meant companies subject to the “AMT” had to carry the credit forward until the company generated enough taxable income relative to its tax attributes to exit AMT. The AMT problem was fixed by the Emergency Economic Stabilization Act of 2008. This legislation made solar more attractive to tax equity investors with other significant tax attributes on their tax returns.

Further, in 2007, if you proposed that Congress should allow solar project owners to trade a project’s ITC for an equal cash payment from the U.S. Department of the Treasury, your knowledge of the political landscape of Washington would have been seriously questioned. In response to the financial crisis, that is what Congress did with the Section 1603 cash grant program enacted in the American Recovery & Reinvestment Tax Act of 2009.

As the solar industry evolved, residential solar exploded. Residential solar started with companies offering homeowners leases of rooftop solar. Power purchase agreements (PPAs) were added to the mix to provide homeowners with a more flexible financing option. The basic PPA structure was then supplemented with a prepaid PPA structure for homeowners flush with cash.

In 2017, loans and cash sales are becoming more popular in the residential market segment, and state programs like the Green Bank in Connecticut or Property Assessed Clean Energy (PACE) programs in states like California and Florida offer homeowners financing at low rates. Debt to finance pools of residential loans, PPAs and leases has been provided in many forms.

Furthermore, in some jurisdictions, due to the advent of community solar, consumers do not even need to own a home or business location to adopt solar. The leading states for community solar are Massachusetts, Minnesota, New York and Vermont, with South Carolina trying to lead the South. Community solar arrangements vary significantly based on the local regulatory regime.

Community solar requires remote net metering rules to be in place. That is, a consumer must be able to earn a credit toward her electric bill for her residence or business, whether such residence or business location is rented or owned, based on electric generation at a utility-scale solar project that may be miles away. For the billing arrangements to work, the utility-scale project must be in the same utility district as the consumer’s residence or business location.

Community solar, depending on the regulatory regime, offers consumers similar financing options as traditional residential rooftop solar: (i) purchase of an undivided interest in the project, with the homeowner claiming a 30% tax credit under Section 25D of the Internal Revenue Code as described in Internal Revenue Service (IRS) Private Letter Ruling 201536017; (ii) a fixed-price lease of an undivided interest, in which the consumer makes a fixed monthly payment in exchange for all of the production from her portion of the project; and (iii) a net metering credit purchase agreement under which the consumer pays for each kilowatt-hour produced by her portion of the project in a particular month. Despite the variation and complexity, developers of community have obtained both tax equity and term debt financing from a variety of sources.

As community solar projects further the goal of democratization of solar, our industry is still left with the criticism that solar is an intermittent resource that is unavailable at night or during periods of cloud cover. To address this challenge, our industry is pursuing energy storage solutions.

Storage is a market segment with tremendous potential for at least three reasons. First, as we saw with respect to solar modules this past decade, efficiency of storage appears to be improving, while costs are declining.

Second, many utilities are recognizing the reliability benefits provided by storage. For instance, Southern California Edison has entered into resource adequacy purchase agreements with 15-year terms for storage under which it pays independent power providers for “capacity attributes,” which are resource adequacy attributes (e.g., the ability to provide power to the grid at key times) identified by the California Public Utilities Commission or California Independent System Operator. Large consumers of energy are incorporating storage to reduce their peak demand charges, sharing the cost savings with storage developers. Still, others are using storage to provide frequency response services.

Third, the IRS ruled, most recently in Private Letter Ruling 201444025, that storage owned by the same taxpayer as a solar project qualifies for the ITC to the extent the storage is at least 75% charged by the solar project – although less than 100% solar charging does result in a proportionate reduction for the ITC for the solar equipment. For instance, 80% solar charging would mean 24% (i.e., 80% multiplied by 30%) of the eligible basis of the storage project would qualify for the ITC.

The IRS announced in Notice 2015-70 that it is going to overhaul the regulations that define ITC eligibility, which were last updated in the 1980s. That overhaul could affect the rules for storage, but we hope any departures in the new regulations from the storage private letter rulings are to remove administratively burdensome requirements, such as the solar charging percentage having to be tested each year during the five-year recapture period, without altering the principle that storage charged with solar qualifies for the ITC.

Some of the fate of the U.S. solar industry over the next six years is dependent on pending IRS guidance as to what it means to “begin construction” of a solar project. This guidance will be important, as it determines what level of the ITC a solar project will qualify for after 2019 as a result of the ratcheting down of the ITC enacted in the Consolidated Appropriations Act of 2016. The IRS is working on that guidance but is taking its time, as it is only relevant starting in 2019 because projects must begin construction by the end of 2019 to qualify for a full 30% ITC. Then, projects that begin construction in 2020 are eligible for a 24% ITC; projects that begin construction in 2021 are eligible for a 22% ITC; and after 2021, current law provides for a permanent 10% ITC. However, regardless of when a project began construction, it must be placed in service (i.e., be operational) by the end of 2023 to qualify for more than a 10% ITC. The IRS issued relatively generous guidance to define beginning construction for wind projects. Our industry is optimistic that the guidance for solar will be no less generous.

The solar industry evolved to overcome the obstacles it faced a decade ago. Given our industry’s ingenuity and drive, it appears likely that it will continue to evolve to successfully address the challenges of today and the coming years.

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